Note: Descriptions are shown in the official language in which they were submitted.
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A METHOD FOR DETERMINING REGIONS FOR STIMULATION ALONG A WELLBORE
WITHIN A HYDROCARBON FORMATION, AND USING SUCH METHOD TO IMPROVE
HYDROCARBON RECOVERY FROM THE RESERVOIR
FIELD OF THE INVENTION
The present invention relates to a method of determining reservoir
characteristics that
can be used to infer best locations along a wellbore to apply well stimulation
and/or hydraulic
fracturing techniques.
BACKGROUND OF THE INVENTION
Fracturing of an underground hydrocarbon formation along a wellbore extending
through the formation by injection of pressurized fluids into the formation
via the wellbore have
been used for a number of years.
Specifically, injection of pressurized fluids in hydrocarbon formations at
pressures
above formation dilation pressures has been used in the past to provide
fractures and fissures
in rock surrounding a wellbore, to thereby stimulate a reservoir to release
hydrocarbons therein
by providing channels within the fractured rock whereby hydrocarbons in the
formation may then
flow through to then be collected.
The fracturing fluid which is provided under pressure may be a non-
compressible fluid
such as water, and/or further containing proppants and/or hydrocarbon diluents
for the purpose
of not only creating fissures in the rock but for further propping and
maintaining the fissures in
an open position to allow hydrocarbons to flow through and/or reduce the
viscosity of oil and
cause it to more readily flow through created fissures in the rock.
Disadvantageously, however, in hydrocarbon formations where the
characteristics of the
formation may not be completely understood or known at all locations in the
formation, injection
of pressurized fluids along an entire length of a wellbore may inadvertently
inject liquids into
regions of the formation where the porosity of the formation at certain
regions may already be
such that such is not needed, or are locations containing relatively less
hydrocarbons, which in
either case such is wasteful of the injected fluid. This is particularly of
concern in instances
around the world where water, which is typically a principal component of the
injected fluid, is
scarce, difficult to obtain, or not available.
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Also disadvantageously, hydrocarbon reservoirs often possess regions of higher
water
content. Fracturing along an entirety of the length of a wellbore and thus in
all regions of a
formation bounding a wellbore will typically undesirably result in fracturing
of rock in one or
more higher water content regions. Such fracturing thereby allows water
therein to more easily
flow out of such regions and into the wellbore, and conversely allows
hydrocarbons to flow
into these regions when water has vacated, thereby detrimentally affecting
recovery of
hydrocarbons through the wellbore.
Accordingly, for the above reasons, indiscriminate fracturing along a
wellbore, without
having intimate knowledge of the in situ geology and in particular the
porosity of the formation
directly in the region of the wellbore often leads to reduced recovery from
the formation via that
wellbore that would otherwise be the case if the porosity and "tightness" of
the hydrocarbons at
various discrete locations along the wellbore was otherwise known.
Accordingly, a real need exists in the petroleum industry of an in-situ method
to allow
reservoir and production engineers to better understand, for a particular
reservoir, the geology
and porosity of the formation in regions bordering the wellbore, and in
particular which regions
of a formation immediately adjacent such wellbore may be "tight" and thus
where hydrocarbons
are potentially trapped and which are in need of stimulation through
fracturing and/or injection
of proppants and/or diluents, as distinguished from other regions of the
formation along a
wellbore which are not as "tight" and for which injection of fluids into such
regions may not
produce as much benefit and/or stimulation thereof which may prove detrimental
to
hydrocarbon recovery.
As regards downhole tools for injecting fluid under high pressures as commonly
used
for conducting fracturing operations, such tools have likewise been known and
used for a
number of years. More recently, however, downhole tools have been developed
which provide
high pressure cyclic pressure surges, instead of a single high pressure, which
is more effective
in providing stimulation as it avoids constant high pressure application to
the formation which
might otherwise displace oil from the region of the wellbore and/or negatively
affect the created
fissures.
Examples of recent downhole tools which provide pulses of pressurized fluid at
pressures in excess of formation dilation pressures to propagate pressure
waves through a
formation are tools/valves such as those described in US 7,806,184 entitled
"Fluid Operated
Well Tool" and US 7,405,998 entitled" Method and Apparatus for Generating
Fluid Pressure
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Pulses", each of said patents commonly assigned to one of the a co-assignees
of the within
invention.
SUMMARY OF THE INVENTION
As used herein, and within the claims, the term "fracturing" or "stimulation"
of a well or
wellbore is intended to mean, and is defined as including, not only fracturing
a formation by
injection of pressurized fluids, such as water, proppants, and the like, but
also includes dilation
or any stimulation whereby any fluids, including gases or combinations
thereof, are injected for
the purpose of changing the absolute or relative permeability of the
formation.
As also used herein and within the claims, the term oil is intended to
include, and is
defined as including all hydrocarbons..
As also used herein and within the claims, the term "wellbore" shall mean any
borehole
within a hydrocarbon formation, either an uncased wellbore or a wellbore cased
with a
perforated or porous casing.
In order to avoid the aforesaid problems with prior art fracturing and
stimulation
techniques which apply indiscriminate fracturing of a wellbore along its
length by applying fluid
pressure at discrete intervals along a wellbore at a pressure above the rock
fracture pressure in
such regions, and to instead provide for customized ( ie optimized) reservoir
stimulation at
intervals along a wellbore where such stimulation will be best put to use, the
invention in a first
broad embodiment thereof provides for a pre-stimulation information gathering
method which
allows for an in-situ determination of relative porosities of regions of the
formation bordering the
wellbore, prior to conducting formation dilation by injection of pressurized
fluid in excess of
formation dilation pressure.
Such pre-stimulation "information gathering" method advantageously allows
determination of the porosities and geology of such regions and provides
valuable quantitative
information as to the relative ease of penetration of fluids in such regions
of the formation by
subjecting various discrete intervals along the length of a collection
wellbore to a pressurized
fluid at a pressure less than formation dilation pressure and/or fracturing
pressure. Analysis of
the ease of penetration of such fluid into the formation at each of the
discrete intervals along the
wellbore, and in particular determining regions of the formation which are
"tight" and in particular
are resistant to fluid penetration allows determination of regions along the
wellbore which would
benefit best from subsequent stimulation, namely injection of a pressurized
fluid at a pressure
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greater than formation dilation pressure or rock fracture pressure in such
regions, to thereby
best utilize such stimulation method in the regions of the wellbore which will
best benefit from
stimulation, and avoid use in regions for which stimulation would not be as
beneficial, or would
be detrimental.
Accordingly, in a first broad aspect of the present invention the invention
relates to a
method for determining along a length of a wellbore situated in an underground
hydrocarbon-
containing formation, regions within said formation along the wellbore where
injection of a fluid
at a pressure above formation dilation pressure may likely be advantageous or
useful for
stimulating production of oil into the wellbore as compared to various other
locations along said
wellbore, comprising the steps of:
(i) applying, via fluid pressurization means, a fluid at each of discrete
intervals along
said wellbore, at a first pressure below formation dilation pressure; and
(ii) sensing, via sensing means, for each of said discrete intervals, a value
or values
indicative of a rate of, a volume of, or extent of, fluid penetration within
each a region of said
formation proximate said discrete interval when said first pressure is
applied, and compiling
said value or values for each associated discrete location along said
wellbore.
The fluid pressurization means may be a tool/valve situated at surface,
wherein
pressurized fluid is pumped downhole, or alternatively may be a tool/valve
which may be
situated downhole in the wellbore, each of which may further be adapted to
apply cyclic
pressure pulses . In an embodiment of the method where a single downhole
tool/valve is
used, such downhole tool/valve may be moved within the wellbore to successive
discrete
locations along the wellbore, and fluid pressure pulses provided at each of
such discrete
intervals (at fluid pressures below formation dilation pressure), in order to
acquire the desired
information regarding ease of fluid penetration at each of the discrete
intervals along the
wellbore.
Alternatively, in another embodiment of using downhole fluid pressurization
means, a
plurality of downhole tools/valves are located downhole, at a plurality of
discrete intervals along
a length of the wellbore. Fluid pressure is then supplied simultaneously to
each of such
downhole tools/valves, in order to simultaneously acquire the desired
information regarding
ease of fluid penetration at each of the discrete intervals along the
wellbore. This refinement of
the method has the advantage of allowing for rapidly determining the regions
within the
formation for subsequent optimal stimulation. The tubing associated with
downhole tools and
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packer elements are then removed from the wellbore, and fluid pressurization
means then
inserted downhole to fracture the formation at only those locations where
stimulation was
determined to be potentially beneficial from the previous information-
gathering step.
Alternatively, if such downhole tools/valves are not removed from the wellbore
and left therein,
such requires those tools that are located in regions determined not to be
beneficial for
subsequent stimulation, to be controlled in a manner, such as by further
having pressure-
actuated sleeves or ball-actuated valves as disclosed in any one of US
4,099,563, US
4,993,678, US 5,048,611, US 7,543,634, or US 7,832,472 located in such tubing
to be used at
each of the various discrete intervals. Such additional sleeves or valves then
serve to prevent
each downhole tool/valve from supplying high pressure fluid to the formation
during the
subsequent stimulation operation to regions where it has been determined that
stimulation
would not be beneficial.
Accordingly, in a further broad aspect of the method, the invention relates to
a method
for determining, along a length of a wellbore situated in an underground
hydrocarbon-
containing formation, regions within said formation along said wellbore where
injection of a
fluid at a pressure above formation dilation pressure may likely be
advantageous or useful
for stimulating production of oil into the wellbore as compared to various
other locations along
said wellbore, comprising the steps of:
(i) placing within said wellbore, at a plurality of discrete intervals along a
length thereof,
fluid pressurization means for supply of a pressurized fluid to the formation
at each of said
discrete intervals along said wellbore;
(ii) applying, via said fluid pressurization means, said fluid at each of said
discrete
intervals, at a first pressure below formation dilation pressure; and
(iii) sensing, via sensing means, for each of said discrete intervals, a value
or values
indicative of a rate of, a volume of, or extent of, fluid penetration within
each a region of said
formation proximate said discrete interval when said first pressure is
applied, and compiling
said value or values for each associated discrete location along said
wellbore.
In a preferred embodiment, a subsequent step (iv) is provided, wherein the
discrete
intervals determined in step (iii) above are then used to determine those
discrete intervals
along the wellbore where fracturing, formation dilation, stimulation, or
injection of fluids at a
pressure above formation dilation pressure, would potentially be desirable to
assist in flow of oil
from said formation at said regions.
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In a refinement of step (iii), step (iii) comprises the step of sensing, via
sensing
means, for each discrete interval, a value indicative of a rate of pressure
decay of said fluid
within a region of said formation proximate said discrete interval and thereby
compiling a
plurality of values at associated discrete locations along said wellbore; and
using the discrete
intervals determined in step (iii) above which have associated values
indicating low rates of
pressure decay to determine those discrete intervals along the wellbore where
fracturing,
formation dilation, stimulation, or injection of fluids at a pressure above
formation dilation
pressure would potentially be desirable to assist in flow of oil from said
formation at said
regions.
In an alternative , the sensing means may provide, for each discrete interval,
a value
indicative of ease of penetration of said fluid supplied at said first
pressure within a region of
said formation proximate said discrete interval; and the discrete intervals
determined in step (iii)
above which have associated values indicating the lowest ease of penetration
of fluid into said
formation being used to determine those discrete intervals along the wellbore
where injection of
fluids a pressure above formation dilution pressure would potentially be
desirable to assist in
flow of oil from said formation at said regions. The ease of penetration of
fluid into said
formation may be determined by:
(a) a measured pressure after a given volume of fluid has been supplied at a
discrete interval in a given time interval; or
(b) a measured volume of fluid supplied at each of said discrete intervals at
a
given pressure in a given time interval;
Thereafter, the discrete intervals determined in such manner may be then used
to determine
those discrete intervals along the wellbore where measured pressure is
highest, or measured
volume of fluid supplied is lowest, to thereby determine regions where
injection of fluids would
potentially be desirable to assist in flow of oil from said formation at said
regions.
For all of the above methods, the foregoing method may further be immediately
thereafter followed by the step of supplying said fluid at a pressure above a
formation dilation
or fracturing
pressure at said one or more discrete intervals along said wellbore as
determined in step (iv) above.
In another aspect of the invention, the invention comprises a method of
determining,
at discrete locations along a length of a porous wellbore situated in a
hydrocarbon-containing
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formation, regions within said formation along said wellbore where fracturing
or dilation via
injection of a fluid may be undesirable or not necessary, comprising the steps
of:
(i) placing within said wellbore, at a plurality of discrete intervals along a
length thereof,
fluid pressurization means;
(ii) applying, via said fluid pressurization means, a fluid at each of said
discrete intervals,
at a pressure below formation dilation pressure;
(iii) sensing, via sensing means, for each discrete interval, a value or
values indicative
of certain reservoir characteristics within a region of said formation
proximate said discrete
interval and thereby compiling a plurality of values and associated discrete
locations along said
wellbore; and
(iv) using the values associated with the discrete intervals as determined in
step (iii) to
determine regions along said wellbore having qualifying reservoir
characteristics to determine
those regions of the wellbore where fracturing, dilation, stimulation, or
injection of fluids would
potentially be undesirable or not useful to assist in flow of oil from said
formation at said regions
into said wellbore.
In a refinement of the above method, step (iii) and (iv) above respectively
further
comprise the steps of:
(iii) sensing, via sensing means, for each discrete interval, a value
indicative of:
(a) a measured pressure after a given volume of fluid has been supplied at a
discrete interval in a given time interval;
(b) a measured volume of fluid supplied at each of said discrete intervals at
a
given pressure in a given time interval; or
(c) a rate of pressure decay of said fluid from a given starting pressure
within a
region of said formation proximate said discrete interval;
and compiling a plurality of said values at associated discrete intervals
along said
wellbore; and
(iv) using the discrete intervals determined in step (iii) above which have
associated
values to determine those discrete intervals along the wellbore where
fracturing, dilation,
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stimulation, or injection of fluids would not be potentially desirable or
useful to assist in flow of
oil from said formation at said regions.
Alternatively, above steps (iii) and (iv) may comprise the steps of:
(iii) sensing, via sensing means, for each discrete interval, a value
indicative of ease
of penetration of said fluid within a region of said formation proximate said
discrete interval and
thereby compiling a plurality of values and associated discrete locations
along said wellbore;
and
(iv) using the discrete intervals determined in step (iii) above which have
associated
values indicating the greatest ease of penetration of fluid into said
formation, to determine
those discrete intervals along the wellbore where via injection of a fluid at
a pressure above
formation dilation pressure would be less likely to be necessary or useful to
assist in flow of oil
from said formation at said regions.
Again, all of the above pre-dilation "information gathering" methods may
further be
followed with the step, after step (iv), of using the fluid pressurization
means to supply fluid
at a pressure above a formation dilation pressure, to the wellbore at one or
more discrete
intervals along said wellbore other than those determined in step (iv), in a
series of cyclic
pressure pulses.
Another aspect of the present invention related to the above information-
gathering
method for determining regions of the formation most likely to benefit from
subsequent
stimulation relies on the fact that regions of the formation determined to
have easy fluid
penetration are likely to be regions in the formation containing higher
amounts of water.
Accordingly, in a further embodiment of the invention such relates to a method
of
reducing, within a hydrocarbon-containing formation, the potential for ingress
of water from
said formation into a porous wellbore situated in said formation, such method
comprising the
steps of:
(i) placing within said wellbore, at a plurality of discrete intervals along a
length thereof,
fluid pressurization means which allow for supply of a pressurized fluid to
said formation at a
localized region proximate each of said discrete intervals;
(ii) applying, via said fluid pressurization means, said fluid at each of said
discrete
intervals, at a pressure below formation dilation pressure;
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(iii) sensing, via sensing means, for each discrete interval, a value or
values indicative
of one or more reservoir characteristics within a region of said formation
proximate said
discrete intervals and thereby compiling a plurality of values and associated
discrete intervals
along said wellbore; and
(iv) using the values associated with the discrete intervals determined in
step (iii) to
determine those discrete intervals which have qualifying associated reservoir
characteristics
which indicate ingress of water into the wellbore at said determined discrete
intervals is a
possibility; and
(v) inserting restriction or barrier means via said wellbore at those discrete
intervals
along the wellbore determined in step (iv), so as to reduce the possibility of
water entering said
wellbore at said discrete intervals.
Again, the value or values sensed by the sensing means may comprise:
(a) a rate of pressure decrease of fluid supplied at said discrete intervals,
over a given
time interval; or
(b) ease of fluid penetration within the formation at each discrete interval,
wherein such
ease of penetration is determined by:
(i) a measured pressure after a given volume of fluid has been supplied at a q
discrete interval in a given time interval; or
(ii) a measured volume of fluid supplied at each of said discrete intervals at
a
given pressure in a given time interval;
In a further broad aspect, the method of the present invention comprises a
method of
fracturing or stimulating via injection of a fluid, a hydrocarbon-containing
formation at discrete
locations along a length of a wellbore situated in said formation, at regions
within said formation
where hydrocarbons are likely present and avoiding applying such methods to
said formation
in regions along said wellbore where such may be unnecessary or undesirable,
comprising the
steps of:
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(i) placing within said wellbore, at a plurality of discrete intervals along a
length thereof,
fluid pressurization means which allow for supply of a pressurized fluid at
each of said discrete
intervals;
(ii) applying, via said fluid pressurization means, said fluid at each of said
discrete
intervals, at a pressure below formation dilation pressure;
(iii) sensing, via sensing means, for each discrete interval, a value or
values indicative
reservoir characteristics at a region of said formation proximate said
discrete interval and
thereby compiling a plurality of values and associated discrete locations
along said wellbore;
(iv) determining , using said reservoir characteristics at said discrete
intervals, where
formation dilation by injection of a fluid at a pressure above formation
dilation would be
potentially beneficial to assist in collection of oil in said wellbore; and
(v) applying cyclic fluid pressure pulses via said fluid pressurization means
,at pressures
above said formation dilation pressure, at one or more of said discrete
intervals along said
wellbore determined in step (iv) above.
The fluid pressurization means for applying cyclic fluid pressure pulses may
be located
uphole, and may comprise an "at surface" tool for pulsed injection of liquids,
and described and
shown in Canadian Patent Application 2,701,261, commonly assigned to one of
the co-
assignees of the present invention.
Alternatively, the fluid pressurization means for applying cyclic fluid
pressure pulses may
comprise a downhole tool, mounted on and at the end of a tubing string from
which it is supplied
with pressurized fluid, such as the downhole wellbore tools /valves described
in US 7,806,184
entitled "Fluid Operated Well Tool" and US 7,405,998 entitled " Method and
Apparatus for
Generating Fluid Pressure Pulses", each of said patents commonly assigned to
one of the a co-
assignees of the within invention.
Still further, the fluid pressurization means for applying cyclic fluid
pressure pulses may
comprise a newly-designed downhole tool, adapted to be mounted on, at a distal
end of a tubing
string located downhole with which it is supplied with pressurized fluid. In
such aspect of the
invention, such new tool for supplying cyclic pressure pulses of fluid
downhole comprises:
a cylindrical elongate member, having an uphole end and a mutually-opposite
downhole
end, adapted for insertion in a wellbore; having:
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(i) a reservoir chamber, situated at said downstream end, said chamber bounded
at an
uphole end thereof by a slidable piston member;
(ii) tubular passageway means, extending substantially a length of said
elongate
member, in fluid communication with said reservoir chamber and providing fluid
communication
between a fluid inlet at said upstream end and said reservoir chamber;
(iii) a fluid exit passage;
(iv) a valve member contacted by said tubular passageway means, having an open
position and a closed position, for allowing and preventing fluid flow from
said inlet area to said
fluid exit passage; and
(v) biasing means biasing said slidable piston member against fluid in said
reservoir
chamber and further biasing said tubular passageway means against said valve
member so as
to bias said valve member to said open position which allows fluid to exit
said tool via said
fluid exit passage.
In operation, upon fluid being supplied to said fluid inlet of such tool at
said upstream
end, and the valve member being in a closed position, fluid pressure in said
reservoir chamber
increases due to fluid supplied to said reservoir chamber from the fluid inlet
via said tubular
passageway means. The slidable piston member is caused to move upstream
against said
biasing means, and the biasing means then forces said tubular passageway means
to move
said valve member to the open position and allowing fluid from said inlet area
to exit the
tool via said exit passage. Fluid exiting the tool via the exit passage
thereby causes an
instantaneous drop in fluid pressure in both said tubular passageway means and
the reservoir
chamber, thereby causing said sliding piston to move downstream in said
reservoir chamber
and allowing said valve member to move to a closed position. The cycle then
repeats for the
tool, and is self-sustaining until fluid pressure supplied from surface is
relaxed or halted.
BRIEF DESCRIPTION OF THE DRAWINGS
The accompanying drawings illustrate one or more exemplary embodiments of the
present invention and are not to be construed as limiting the invention to
these depicted
embodiments. The drawings are not necessarily to scale, and are simply to
illustrate the
concepts incorporated in the present invention.
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Fig. 1 shows a cross-sectional view of a wellbore using a method of the prior
art for
stimulating regions within a hydrocarbon-containing formation. A pressurized
fluid supply tool,
interposed between two packer elements and located at the distal end of tubing
inserted
downhole in a wellbore, is supplied with fluid under a pressure exceeding
wellbore dilation
pressure, which causes fracture of rock in the formation surrounding the
wellbore;
Fig. 2
is a cross-sectional view of a wellbore using the "information-gathering"
method of the present invention, for obtaining reservoir characteristics of
the formation at a
series of discrete locations along the wellbore, showing a pressurized fluid
supply tool
interposed between two packer elements and located at the distal end of a
tubing, wherein
sensor means are located at discrete intervals along the wellbore, and the
pressurized fluid
supply tool is located at a first of said discrete intervals along the
wellbore;
Fig. 3 is a similar cross-sectional view of a wellbore using the "information-
gathering"
method of the present invention, at a further successive step in the method,
where the fluid
pressurization means has been subsequently re-positioned to a second of such
discrete
intervals along the wellbore, and fluid at a pressure less than formation
dilation pressure is
supplied;
Fig. 4 is a similar cross-sectional view of a wellbore using the "information-
gathering"
method of the present invention, at a further successive step in the method,
where the fluid
pressurization means has been subsequently re-positioned to a third of such
discrete intervals
along the wellbore, and fluid at a pressure less than formation dilation
pressure is supplied;
Fig. 5 is a similar cross-sectional view of a wellbore using the "information-
gathering"
method of the present invention, at a further successive step in the method
where the fluid
pressurization means has been subsequently re-positioned to a fourth of such
discrete
intervals along the wellbore, and fluid at a pressure less than formation
dilation pressure is
supplied;
Fig. 6 is a similar cross-sectional view of a wellbore using the "information-
gathering"
method of the present invention, at a further successive step in the method,
where the fluid
pressurization means has been subsequently re-positioned to a fifth of such
discrete intervals
along the wellbore, and fluid at a pressure less than formation dilation
pressure is supplied;
Fig. 7 is a similar cross-sectional view of the wellbore , after completion of
the above
"information gathering" steps, wherein the fluid pressurization tool is
positioned at a first location
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in the wellbore where is was determined by the foregoing "information
gathering" steps that
stimulation would be beneficial, wherein such pressurization tool is provided
with fluid under
pressure at the pre-determined desired interval, and stimulation of the
surrounding rock is being
carried out;
Fig. 8 is a similar cross-sectional view of the wellbore , after completion of
the above
"information gathering" steps, wherein the fluid pressurization tool is
positioned at a second
location in the wellbore where is was determined by the foregoing "information
gathering" steps
that stimulation would be beneficial, wherein such pressurization tool is
provided with fluid under
pressure at one of the pre-determined interval, and stimulation of the
surrounding rock is being
carried out at such interval;
Fig. 9 is a cross-sectional view of another embodiment of the method of the
present
invention, wherein a vertical well is employed, and the "information-
gathering" step has been
carried out along discrete intervals along such vertical well and a particular
distinct interval
therealong as been identified as having characteristics for which stimulation
may be beneficial,
and a downhole tool is being used to provide stimulation of surrounding rock
at such identified
interval;
Fig. 10A is a plan view of a downhole tool/valve of the present invention for
applying
cyclic fluid pressure pulses, adapted to be mounted at a distal end of a
tubing string (which
tubing string may be continuous or coiled tubing, or discrete pipe lengths),
which supplies such
downhole tool/valve with pressurized fluid,
Fig. 10B is a cross-sectional view of the tool shown in Fig. 10A, taken along
the
longitudinal axis thereof, when the tool/valve is in the "closed" position;
Fig. 10C is a cross-sectional view of the tool shown in Fig. 10A, taken along
the
longitudinal axis thereof, when the tool/valve is in the "open" position for
supplying pressurized
fluid to a discrete location along a wellbore;
Fig. 11A is a plan view of another version of the downhole tool/valve of the
present
invention, similar to that shown in Fig. 10A;
Fig. 11B is a cross-sectional view of the tool shown in Fig. 11A, taken along
the
longitudinal axis thereof, when the tool/valve is in the "closed" position;
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Fig. 11C is a cross-sectional view of the tool shown in Fig. 11A, taken along
the
longitudinal axis thereof, when the tool/valve is still in the "closed"
position with the metering
valve remaining seated, but with pressurized fluid being supplied to the
tool/valve;
Fig. 11D is a cross-sectional view of the tool shown in Fig. 11A, taken along
the
longitudinal axis thereof, when the tool/valve is in the "open" position for
supplying pressurized
fluid to a discrete location along a wellbore; and
Fig. 12 depicts a cross-sectional view of a wellbore using a modified form of
the
"information-gathering" method of the present invention, which advantageously
is able to
gather information simultaneously along the entirety of the wellbore.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
With reference to the drawings Fig.'s 1-12, like or similar elements are
designated by
the same reference numeral through several views and figures. However, such
elements are
not necessarily shown to scale in drawings Fig.'s 1-12.
Fig. 1 shows a cross-sectional view of a hydrocarbon- containing formation 10
having a
horizontal wellbore 12 drilled within a "pay" zone 14 thereof, which depicts a
prior art method
of fracturing regions 15, 16, 18, and 20 of hydrocarbon-containing formation
10, with region 18
shown being fractured by fluid pressurization via tool 24, thereby creating of
fissures 21 within
rock surrounding wellbore 12. In such prior art method, a fluid pressurization
means, such as a
downhole tool/valve 24, interposed between two double-packer elements 26, 28
and located at
the distal end 30 of a tubing 32, which may be continuous tubing, coiled
tubing, or discrete
pipe lengths threadably coupled together, is inserted downhole in wellbore 12
for providing
cyclic pressure pulses, at a pressure above formation dilation pressures, at
various discrete
intervals along wellbore 12, to cause formation dilation and/or fracturing of
rock in the formation
10. Specifically, in such prior art method depicted in Fig. 1, downhole
tool/valve 24 is supplied
with fluid under a pressure exceeding wellbore dilation pressure, which causes
fracture of and
fissures 21 in rock within formation 10, and in particular within region 18
surrounding the
wellbore 12. Downhole tool/valve 24 is subsequently repositioned to other
remaining discrete
intervals along wellbore 12, so as to successively fracture regions 15, 16 and
20 along wellbore
12, so that the formation 10 is fractured along the entirety of the length of
wellbore 12 and thus
at each of regions 15, 16, 18, and 20 therealong. a cross-sectional view of a
hydrocarbon-
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containing formation 10 having a horizontal wellbore 12 drilled within a "pay"
zone 14 thereof,
which depicts a prior art method fracturing exemplary regions 16, 18, and 20
of hydrocarbon-
containing formation 10, with region 18 shown being fractured by the creation
of fissures 21
within rock surrounding wellbore 12.
Notably, hydrocarbon-containing formations 10 typically are non-homogenous,
possessing distinct regions such as regions 16, 18, and 20 through which
wellbore 12 passes
and which thus border wellbore 12. Each of separate distinct regions such as
regions 16, 18,
and 20 which are shown for illustrative exemplary purposes, typically possess
distinct and
separate geological properties (ref. Fig. 1) , such as of different densities
and porosity, rock
type (and whether such rock is of a consolidated or unconsolidated nature),
and each of varying
levels of oil and water saturation.
Thus disadvantageously, as explained in the "Background of the Invention"
herein, where the characteristics of the formation 10, and in particular the
geology, individual
properties of, and number of, distinct regions with formation 10, and in
particular in such
regions as regions 16, 18, and 20 which border wellbore 12 may not be
completely understood
or known as to all properties, and thus injection of pressurized fluids along
an entire length of a
wellbore 12 may inadvertently inject liquids into regions of formation 10 such
as, for example,
region 18 of the formation 10, where the porosity of the formation at such
region 18 may already
be such that stimulation is not needed. Thus indiscriminate stimulation in
regions immediately
surrounding wellbore 12 , such as region 18 which may be sufficiently porous
and/or or of a
geology to not require dilatation, results in wastage of fluid and delay in
completing stimulation
along wellbore 12. Wasteful use of injected fluid is of particular concern in
locations around
the world where sources of surface water to be pumped downhole (water being
typically a
principal component of the injected fluid) is scarce and difficult to obtain.
Also disadvantageously, hydrocarbon reservoirs often possess regions of higher
water
content and higher water saturation. Stimulation along an entirety of the
length of a wellbore 12
and thus in all regions 16, 18, and 20 of a formation 10 bounding a wellbore
12 will typically
undesirably result in stimulation of rock in one or more higher water content
regions. Such
stimulation thereby allows water therein to more easily flow out of such
regions such as region
18 and into the wellbore 12 , and conversely allows oil to flow into these
regions 18 when
water has vacated, thereby detrimentally affecting recovery of hydrocarbons
through the
wellbore 12.
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Accordingly, for the above reasons, indiscriminate stimulation methods of the
prior art
which fracture formation 10 along an entire length of a wellbore 12, or even
in selected lengths
without having intimate knowledge of the in situ geology and in particular the
porosity of the
formation 10 in each of regions along and proximate wellbore 12 often leads to
reduced
recovery from the formation 10 than would otherwise be the case if the
porosity and
"tightness" of the hydrocarbons in the reservoir 10 near each and all of the
discrete intervals
along the wellbore 12 was otherwise known, or known with greater precision.
The method of the present invention, as shown schematically in Fig.s 2- 6, and
Fig. 12,
provides an initial information-gathering step to be carried out at pressures
below formation
dilation pressures, prior to conducting actual fracturing or formation
dilation at pressures
above formation dilation pressures, as shown in Fig.s 7,8. Such information-
gathering method
allows initial acquisition of information as to reservoir/formation
characteristics, in particular
information as to ease of fluid penetration at discrete intervals along the
entirety of the length of
wellbore 12 (ie information with regard to the formation in regions directly
bordering the
wellbore 12), namely those regions such as for example regions 15, 16, 18, 20,
and 22
bordering wellbore 12 and extending outwardly therefrom, to allow
identification of optimum
locations for a subsequent stimulation operation.
One of the methods of the present invention is depicted in the successive
series of steps
shown in successive figures Fig.s 2-6 herein.
In this regard, Fig. 2 depicts an initial step in such method. Fluid
pressurization means
in the form of a downhole tool/valve 24 is first interposed between two packer
elements 26, 28
and located at the distal end 30 of tubing 32. Downhole tool 24 and associated
packers 26, 28
are thereafter inserted via such tubing 32 downhole in wellbore 12, at an
initial discrete interval
along wellbore 12, as shown in Fig. 2 . When the downhole tool/valve 24 is
positioned at such
initial discrete interval, a fluid such as water is supplied to such valve 24,
at a pressure less
than formation dilation pressure. A plurality of sensors 70 are provided at
spaced discrete
intervals along wellbore 12.
In one embodiment communication line 74 comprises a plurality of electrical
lines, with
each individual sensor 70 in electrical communication therewith via
corresponding electrical
feeder lines 77, all in electrical communication with communication line 74
and thus with
surface. Other means and manners of sensors 70 being in communication with
surface will now
be apparent to persons of skill in the art, such as by fibre optic cable or
such other means, such
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as single bus line 74 with separate channels for each sensor 70.
Communication line(s) 74 is/are in communication with recordal means 60 at
surface.
Recordal means 60 is provided for electronically receiving and storing
information, as more fully
explained below, which is supplied by sensors 70, and may comprise a personal
computer
having a hard drive or flash memory (not shown), and may further comprise
multiplexing means
(not shown) if only one communication line 74 is used in order to be able to
receive and record
data simultaneously from sensors 70, which may be numerous depending on the
spacing of the
discrete intervals and the length of wellbore 12.
Only one sensor 70 need be used with the method shown in Fig. 2-6, which
sensor 70
progressively moves in conjunction with downhole tool 24 from discrete
interval to subsequent
discrete interval. Alternatively a plurality of sensors 70 may be employed as
shown in Figs. 2-
8, with a respective sensor 70 providing information/data for each particular
discrete interval.
Sensor(s) 70 are adapted to provide very localized data/information as to the
ease of
penetration of fluid through a particular region of the formation 10 proximate
a given discrete
interval along the wellbore 12 at which an individual sensor 70 is located.
Sensors 70, alone or
in combination with recordal means 60 [recordal means 60 may not only provide
a data
recordal function, but may further provide subsequent data manipulation, such
as to convert raw
flow rates of fluid into flow rates per a given measured time interval for
each of the respective
discrete locations] , are each adapted to sense one or more of the following
parameters:
(i) rate of pressure decrease within the region of the wellbore 12 bounded by
the porous
wellbore 12 (which has apertures therein to allow egress of fluid under
pressure into
regions 15, 16, 18 & 20 of the formation 10), and each of the packer elements
26, 28,
over a given interval of time. For such purposes numerous existing pressure
sensing
devices 70 may be suited, provided each adapted to withstand temperatures and
pressures to which the devices may be subject downhole;
(ii) volume of fluid forced into a particular region (eg in Fig. 2, region 15)
during a
particular time interval. In such instance, volumetric measurement of supplied
fluid
supplied via tubing 32 is likely most easily determined from a sensor 70
positioned at
surface, and need not be located downhole; and/or
(iii) the extent of penetration of fluid into regions of the formation. In
such case, such
sensors 70 may comprise electronic probes which sense variations in electrical
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resistivity or conductivity of the formation 10 in the regions such as region
15 which is
the particular region 15 being subjected to fluid penetration from tool/valve
24 in Fig. 2,
both before and after being subject to such fluid pressure via tool/valve 24,
relying on
the principal that the electrical resistivity/conductivity of formation 10 is
dependent on the
extent of water saturation, particular where the saturating water contains
brine as is
frequently and often the case in underground formations and/or the injected
fluid being
injected via tubing 32 and downhole tool/valve 24 is an ionic electrically
conductive
fluid. Sensors 70 in such embodiment comprise one half member of a pair of
electrical
probe members, with the other corresponding probe members being located along
similar spaced discrete distances on top of, or within each region 15, 16, 18,
& 22, to
thereby measure the electrical resistivity of a region before, and after,
being subjected
to fluid pressure, to thereby obtain relative comparable value as between the
regions
15, 16, 18, 20 and 22 as to the extent of fluid penetration within a
particular region
relative to other regions.
Fig.s 3, 4, 5, & 6 further depict successive stages of the information
gathering method of
the present invention, showing successive movement of the downhole tool 24 and
associated
packer elements 26, 28 along wellbore 12 toward and up to the toe of wellbore
12, with
successive application of fluid pressure via tool 24 at each of respective
successive discrete
intervals along wellbore 12 for supply of pressurized fluid to successive
regions 16, 18, 20, and
22 of formation 10, with the gathering by sensor (s) 70 of the above
information/data at each of
the respective discrete intervals shown in Figs. 3-6.
Fig. 12 shows an alternative embodiment of the method of the present
invention.
In such method shown in Fig. 12, a plurality of downhole tools 24 are
provided, each
interposed between respective packers 26, 28 which together provide a
respective pressure
seal within wellbore 12 so as to prevent fluid from downhole tool 24 from
passing upwell or
downwell and thereby ensure that the fluid is directed through porous wellbore
12 and into
regions 15, 16, 18,20 and 22. Wellbore 12 may be comprised of well casing
having screens or
apertures (not shown) therein] to allow fluid communication with regions 15,
16, 18, 20, and 22
which allow, to a measured extent, fluid penetration into respective regions
15, 16, 18, 20, and
22 of formation 10. In this method all of downhole tools/valves 24 and
associated packer
elements 26, 28 are positioned at the end of tubing 32 and inserted downhole
within the length
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of a wellbore 12.
In this method, pressurized fluid is applied simultaneously to each of the
five(5) discrete
intervals along wellbore 12, and sensors 70 provide data relative to the ease
of penetration of
the fluid within each of the respective regions 15, 16, 18, 20 and 22 along
wellbore 12.
Thereafter, upon analysis of the data obtained from sensors 70 via
communication line 74
indicating relative ease of penetration of fluids within various regions of
formation 10, as
recorded by recordal means 60, those regions having poor ease of penetration
(such as for
example, regions 18 and 20) can be individually and successively selected for
subsequent
stimulation, for example supply of a pressurized fluid at pressures above
formation dilation
pressures, so as to cause fracturing and fissures 21 in the rock surrounding
wellbore 12, as
shown in successive Figs. 7 & 8.
Fig. 9 is an example where the method of the present invention may be adapted
for use
in a vertical wellbore 12, instead of the horizontal wellbore 12 depicted in
Fig.s 2-8. The
method and apparatus used are identical to the method disclosed in Fig.s 2-8.
Fig.'s 8 & 9 shows respectively application of fluid pressures, at pressures
above
formation dilation pressures, to respective regions 18, 20 determined by the
information-
gathering portion of the method of the present invention, to be regions of
poor fluid penetration
and to be regions which would likely benefit from subjection to fluid under a
pressure in excess
of formation dilation pressure.
Figs. 10A to Fig. 10C show a novel downhole tool/valve 24, useful for applying
cyclic
fluid pressure pulses, at either the initial information-gathering stage of
the present invention,
and/or the formation dilation stage of the present invention, possessing a
single biasing member
in the form of a spring 100.
With respect to the downhole tool/valve 24 shown in Fig.'s 10A-10C, Fig. 10A
is a
exterior plan view thereof, comprising a cylindrical elongate member 125,
having an uphole end
112 located on the left hand side of Fig. 10A, and a downhole end 114 thereof
located at a
mutually opposite end on the right hand side of Fig. 10A.
Each of Fig.s 10B and Fig. 10C are cross-sectional views through the tool of
Fig. 10A,
with the tools/valve 24 shown in the "closed" position in Fig. 10B, and in the
"open" position in
Fig. 10C.
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A reservoir chamber 130 is provided, situated at the downhole end 114, and
bounded
by a plug member 117 at the downhole end 114, and by a slidable piston 122. A
tubular
passageway 140 extends substantially a length of said elongate member 125, and
is in fluid
communication with reservoir chamber 130 and provides fluid communication
between a fluid
inlet 150 at said uphole end 112 and reservoir chamber 130.
A fluid exit passage 155 is provided in elongate member 125, which allows for
controlled egress of fluid from tool/valve 24, wherein fluid flow through exit
passage 155 is
controlled by valve member 165. Valve member 165 is contacted by tubular
passageway
140, and has an open position (Fig. 10C) and a closed position (Fig. 10B), for
allowing and
preventing fluid flow respectively from said fluid inlet 150 to said fluid
exit passage 155.
Biasing means, in the form of helical spring member 100, is provided, and
functions to
bias slidable piston 122 against fluid in reservoir chamber 130 and further
biases tubular
passageway 140 against said valve member 165 so as to bias said valve member
165 to said
open position which allows fluid to exit said tool 24 via said fluid exit
passage 155.
In operation, upon fluid being supplied to fluid inlet 150 at said uphole end
112 of
cylindrical member 125 and valve member 165 being in a closed position, fluid
pressure in
reservoir chamber 130 increases due to fluid supplied to said reservoir
chamber 130 from the
fluid inlet 150 via said tubular passageway 140, as shown in Fig. 10B.
Thereafter, slidable piston 122 is caused to move uphole against said spring
100, until
such point as spring 100 is provided with sufficient compressive force to then
suddenly force
tubular passageway 140 to move valve member 165 to said open position as shown
in Fig.
10C, and thereby allow fluid from said fluid inlet 150 to exit the tool 24 via
said exit passage
155. Egress of fluid via passage 155 thereby causes a drop in fluid pressure
in both said
tubular passageway 140 and reservoir chamber 130, thereby causing said sliding
piston 122 to
move downhole into reservoir chamber 130, thereby reducing the force exerted
by spring 100
and thus allowing valve member 165 to move back to a closed position as shown
in Fig. 10B.
Figs. 11A to Fig. 110 show another novel alternative configuration for a
downhole
tool/valve 24', likewise useful for applying cyclic fluid pressure pulses at
either the initial
information-gathering stage of the present invention and/or the formation-
dilation stage of the
present invention
The novel tool/valve 24' of Figs. 11A-11D, in comparison to the tool/valve 24
shown in
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Fig.'s 10A-10C , possesses an additional biasing member 110 - all remaining
components of
tool/valve 24', and the manner of operation of valve/tool 24' and its
components being
substantially the same as the manner of operation and components described
above in regard
to the tool/valve 24 shown in Figs. 10A-10C.
The reason for the desirability of adding a second spring 110 is that the
tools/valves 24,
24' are basically a vibrational reciprocating devices, having an applied
forcing function (the
pressure of the fluid applied). Frequently a production engineer will wish to
provide cyclic
pulses at no greater than a given frequency, as pressure pulses compressed to
too short a time
interval (ie at too high a frequency) will negate the benefits of providing
spaced- apart pressure
pulses, and possibly vibrate regions of the formation to such an extent that
unconsolidated rock
within formation 10 is caused to fall undesirably closer together, much like
shaking contents of
containers which causes contents therein to settle and occupy a lesser total
volume.
However, the cyclic frequency by which the tool/valve 24, 24' operates (where
no
vibrational control is imparted at surface to the fluid supplied) is
determined by such variables
as the actual pressure of the fluid supplied to the valve 24 or 24' at inlet
150, the viscosity of the
fluid and thus the consequent metering (damping) of fluid flow achieved in
tubular passageway
140, the stiffness and length of the springs 100 and 110, and the mass of
tubular passageway
140 and sliding piston 122, as well as the damping resulting from slidable
frictional movement of
such components within cylindrical member 125. Some of these variables the
well production
engineer may have little control over, and may wish to adjust the pressure
pulse frequency by
adjusting the parameters of the tool 24' directly over which he/she may have
control.
Accordingly, by adding one additional spring 110 to the tool 24 of Fig.s 10A-
10C,
thereby effectively increasing the total length (and compression of) the
springs 100, 110, where
the added spring 110 may further be of a greater or lesser stiffness and/or a
greater or lesser
length than, first spring 100 of tool 24, additional ranges of adjustment of
the vibrational system
can be achieved for the tool 24' to thereby permit an optimal cyclic pressure
pulse to be
provided by tool 24' to the formation 10. In particular such modified design
24' allows the
provision of pressure pulse frequency of an acceptable high pressure, but at a
frequency
lower than would otherwise be achievable for a tool having only a single
spring 100.
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The scope of the claims should not be limited by the preferred embodiments set
forth in
the foregoing examples, but should be given the broadest interpretation
consistent with the
description as a whole, and the claims are not to be limited to the preferred
or exemplified
embodiments of the invention.
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